The present invention relates generally to the oil and gas industry and in particular to oil well production utilizing reciprocating pumps.
Oil wells are produced using a variety of methods ranging from self-production, where the formation pressure is high enough to cause the oil to flow up the wellbore, to various forms of artificial lift, where the formation pressure is insufficient and cannot lift the hydrocarbon fluid up the wellbore. The most common artificial form used in the oil industry is the reciprocating pump.
The standard industry reciprocating pump consists of a prime mover that is positioned at the surface, and a pumping barrel that is positioned within the production tubing at or near the bottom of the wellbore. The wellbore is lined with steel pipe called casing.
The production tubing is concentric within the casing and is the conduit through which produced fluids are sent to the surface. The area between the production tubing and the casing (wellbore) is called the annulus. The production tubing is generally suspended from the surface and xe2x80x9crestsxe2x80x9d against the casing forming a seal at the surface. The steel casing has a series of holes or perforations punched in the casing where the producing formation is found, that allow the formation fluid to enter the annulus.
The production tubing has a xe2x80x9cseating nipplexe2x80x9d at the formation end of the tubing into which the pump will seat. The tubing may be terminated in a rounded end with a series of perforations that act as a course filter and allow the formation fluid to enter the production tubing. The seating nipple has a reduced inside diameter when compared to the tubing that forms a hold-down into which the pump barrel locks or is held-down. The barrel is locked into place within the production tubing so that a seal is formed between the pump and the production tubing. This seal keeps the produced fluid from re-entering the formation.
There are two ways by which the pump at the end of the production tubing is driven (reciprocated). The first uses the industry standard sucker rods, and the second uses a new technique that employs a wire cable. Both the cable and the sucker rod string terminate at the pump and at the prime mover. A cable driven pump will employ the same (or similar) pull rod at the downhole end plus a set of sinker (weighted) rods.
After a period of time, the downhole pump must be serviced, and the cable or sucker rod string is employed to lift the pump up and out of the well. The pump is pulled up to the surface within the production tubing. A certain amount of force is required to xe2x80x9cpopxe2x80x9d the pump loose from the hold-down at the bottom of the production tubing.
Very often the force to xe2x80x9cpopxe2x80x9d the pump loose is excessive and is caused by build-up of xe2x80x9cflower sandxe2x80x9d around and about the pump at the hold-down. Flower sand is entrained in the produced fluid and tends to precipitate from the fluid as it passes up the production tubing. The sand then falls to the bottom of the tubing and xe2x80x9cpacksxe2x80x9d around the hold-down thereby substantially increasing the force required to xe2x80x9cpopxe2x80x9d the pump loose from the hold-down.
Furthermore because there are series of ball and check valves within the pump (the associated standing valve), the initial force required to xe2x80x9cpopxe2x80x9d the pump loose must also pull against the hydrostatic head contained within the production tubing which thereby increases the required unseating force. As the depth of the well increases, the weight of the produced fluid increases: essentially, the weight of produced fluid is related to the hydrostatic head contained within the production tubing. As soon as the pump pops loose the hydrostatic head will reduce because the fluid in the production tubing will U-tube within the annulus and tubing.
There have been instances when the sucker rod string breaks in two, due to the high force required to xe2x80x9cpopxe2x80x9d the pump loose, thus leaving the pump in the tubing. At this point, the well operator must pull the production tubing to retrieve the pump: an expensive operation. In the case of the wire cable driven pump, the wire cable is often limited in pulling force, and the tubing would have to be pulled.
Among some of the prior art attempting to solve the problem caused by sand buildup and hydrostatic head are: Hall (U.S. Pat. Nos. 5,018,581 and 4,103,739), Hix (U.S. Pat. No. 3,994,338), Howe (U.S. Pat. No. 3,150,605), Owen (U.S. Pat. No. 4,909,326), Soderberg (U.S. Pat. No. 4,645,007) and Sutliff et al. (U.S. Pat. No. 4,273,520. Hall envisions an auxiliary valve-like device that is placed at some point (mid) in the pump barrel as the barrel is being made up. This valve opens during withdrawal of the pump if the pulling force exceeds a predetermined force caused by sand buildup. If the device does not open, then it is assumed there is no sand buildup and the device may be re-inserted into the wellbore.
Hix describes a frangible rupture disk that is placed between the standing valve and the hold down in a barrel pump assembly. The rupture disk is activated by increasing the pressure in the standing column of produced fluid; thus, some sort of pumping device is required at the surface. The device also incorporates a left hand thread that allows the pump to be unscrewed if the rupture disk fails to rupture. This is a one shot device.
Howe illustrates a complex ball and seat device that is placed at the pump head and drains the tubing fluid above and around the pump whenever the pump is raised out of the tubing. It does not release the hydrostatic head in the tubing.
Owen portrays a tubing unloader that is placed in the tubing itself. As the tubing is pulled upward the unloader opens and allows the entrapped fluid to drain back into the annulus.
Soderberg also describes a tubing unloader that is placed in the tubing like the device of Owens. However, the Sonderberg device uses an increase in fluid pressure to open the device. Again this implies some sort of pump source at the surface. Finally, Sutliff et al. disclose a deep well pump that incorporates a drain valve that allows the pump to drain within the tubing so that the pump is basically pulled dry from the well.
The industry has attempted to solve the flower sand problem by using a bottom discharge valve mounted below the pump and above the lower check valve (stationary valve), that allows back flow of produced fluid within the production tubing, thereby causing a swirl that hopefully picks up the sand about the hold-down reducing the force required to xe2x80x9cpopxe2x80x9d the pump loose. The valve which is really a second check valve that, on the downstroke, allows flow of produced fluid from the pump barrel into the tubing (Note the valve is spring loaded so that downward force is required to force the produced fluid backwards into the tubing.) The by-passed flow causes a swirl around the bottom section of the pump and up into the tubing. The device helps but, because it is located away from the hold-down and because the backflow fluid still remains within the tubing, it is somewhat inefficient when washing sand. The force required to push the fluid through the bottom discharge valve is supplied by the weight of the sucker rod string (coupled through the pull rod). The required force (xe2x80x9cweightxe2x80x9d) is unavailable in a cable driven pump. (xe2x80x9cOne cannot push on a rope.xe2x80x9d) The industry has not resolved the hydrostatic head problem.
Furthermore, the industry must inject corrosion control chemicals into and about the pump. The dead flow area between the pump barrel and the production tubing presents a problem because there is no known method (or apparatus) to place (spot) chemicals in this area. Current methods dump chemicals down the annulus or down the production tubing where the chemical can migrate throughout the system where fluid flow is occurring. Since there is no flow between the barrel and the production tubing, corrosion control chemicals cannot currently be spotted in that area.
Thus, there remains a need for a device that will wash the flower sand buildup from about the hold-down within the production tubing and/or reduce hydrostatic head, thereby reducing the force required to xe2x80x9cpopxe2x80x9d a pump loose for servicing. The need is even higher for cable driven pumps. There also remains a need for equipment and a method for spotting chemicals in a well.
The first embodiment (prototype) device is about 12 to 18 inches long, consists of three parts and is run between the ball and seat and the hold down stinger prior to being placed in the wellbore. The embodiment is preferably used with barrel pumps. The first part is the outer barrel that attaches to a standard hold-down stinger. The second part is a hollow moving piston within the barrel. The third part is header that attaches to the piston and connects to the standing valve. In the barrel pump method the device is attached to the barrel (via the standing valve) and lowered into the well; whereas, in the tubing pump method the complete assembly is dropped into the well. Produced fluid normally flows from the hold-down stinger, through the hollow piston, through the header, through the ball and seat assembly of the standing valve and into the pump.
The first embodiment prototype piston has two sets of apertures or ports, a vent aperture set and a dump aperture set, and a series of seal O-rings. The O-rings and apertures remain within the barrel until activated by forces applied from the surface. The header also serves as a valve (referred to as the xe2x80x9chead valvexe2x80x9d) and has a wedge like shape (opposite the end of the header that attaches the standing valve) that will mate with the top (end opposite the hold-down stinger) of the barrel forming a seal. The two sets of apertures, if exposed from within the barrel, will allow fluid to flow from the production tubing into the annulus.
The first embodiment prototype device has four xe2x80x9cpositions.xe2x80x9d The entry position, the closed position, the vent position and the dump position. The entry position is the initial position and is kept in this position by an entry shear-pin(s). In the entry position, the head valve is approximately xc2xd-inch away from the barrel, thus, keeping the head valve open; however, the xe2x80x9cventxe2x80x9d aperture and the xe2x80x9cdumpxe2x80x9d aperture remain xe2x80x9clockedxe2x80x9d within the barrel and sealed by O-rings. No fluid can pass from within the hollow piston and the outside of the barrel. Produced fluid only flows from the formation into the pump and onto the surface. (It may not be necessary to employ the entry position when utilizing the instant device in a tubing pump and the entry shear pins may be left out.)
Allow some time to pass and sand to build up around the hold-down stinger. The operator allows the reciprocating system to drive the device downwards toward the bottom of the well. This action shears the xe2x80x9centryxe2x80x9d shear pin(s) and allows the head valve to come into contact with the barrel; thereby, placing the device in the closed position. The operator then draws up on the reciprocating system causing the piston to move upwards within the barrel to the xe2x80x9cventxe2x80x9d position. This position allows fluid within the tubing to back flow into the annulus through the stinger at the bottom of the tubing. A large portion of the flower sand drops out in the rat-hole. (The rat-hole is that portion of the wellbore that deliberately left below the perforations for the purpose of receiving wellbore debris.) After a reasonable period of time, the reciprocating system is returned to normal. This allows the vent aperture to slide back into the piston thereby terminating reverse fluid flow and returning to the closed position. A series of O-rings would normally assure that no fluid can continue to reverse flow; however, if the O-rings become damaged, the head valve will cutoff reverse flow. This process is repeated as needed.
Now allow that the pump needs to be removed for service. The operator draws up on the reciprocating system causing the piston to move upwards within the barrel to the xe2x80x9cventxe2x80x9d position. Additional force is required to shear the xe2x80x9csafety-pinxe2x80x9d within the barrel. The safety pin prevents the larger xe2x80x9cdumpxe2x80x9d aperture(s) from allowing reverse flow. Additional upward force is then applied that shears the xe2x80x9csafety-pinxe2x80x9d. This then allows the piston to move further upward exposing the larger xe2x80x9cdump port(s) or aperture(s)xe2x80x9d which allows increased reverse flow. The increase in reverse flow will further wash sand and allow the hydrostatic head to dissipate into the annulus thereby reducing the total pull required to xe2x80x9cpopxe2x80x9d the pump loose and withdraw it from the well.
The second embodiment prototype piston was developed after a series of field experiments determined that two sets of apertures were not always necessary and the concept of the device could be handled by one set of apertures. (In fact, a set of apertures may range from one to a plurality depending on the total hydrostatic head.) This embodiment is also preferably used with the barrel pump and is slightly shorter than the prototype. The second embodiment piston has a single set of apertures, called vent-dump ports or aperture(s) or venting ports or aperture(s), and a series of seal O-rings. The term venting aperture(s) is used to differentiate between the two embodiments. The O-rings and aperture(s) remain within the barrel until activated by forces applied from the surface. The vent-dump or venting aperture(s), if exposed from within the barrel, will allow fluid to flow from the production tubing into the annulus.
The second embodiment device has three positions because the vent position in the prototype embodiment was found to be unnecessary. These positions are the entry position, the closed position and the vent-dump or venting position. (The term venting is used to differentiate between the two embodiments). As with the first embodiment, the entry position is the initial position and is kept in this position by an entry shear pin or a set of entry shear pins. In the entry position, the header is approximately xc2xd-inch above the barrel and the upper valve or head valve is held open. At the same time the xe2x80x9cvent-dumpxe2x80x9d or xe2x80x9cventingxe2x80x9d aperture(s) remain(s) xe2x80x9clockedxe2x80x9d within the barrel and sealed by O-rings. No fluid can pass from within the hollow piston and the outside of the barrel. Produced fluid only flows from the formation into the pump and onto the surface.
Allow some time to pass and require that the system be serviced. The operator allows the reciprocating system to drive the device downwards toward the bottom of the well. This action shears the xe2x80x9centryxe2x80x9d shear pin(s) and allows the header to come into contact with the barrel; thereby further closing the device. The device is now xe2x80x9ccockedxe2x80x9d (capable of being opened) but is in the closed position. That is the upper sloped valve or head valve (the area between the header and the barrel) is closed and initially the venting aperture(s) are sealed (by O-rings) within the barrel.
The operator then draws up on the reciprocating system causing the piston to move upwards within the barrel towards the top of the device. Additional upward force is required to shear the xe2x80x9csafety-pinxe2x80x9d within the barrel. This then allows the piston to move further upward exposing the xe2x80x9cventing aperture(s)xe2x80x9d that allow(s) for reverse flow. The reverse flow may be shut off by releasing the upward force thereby placing the venting aperture(s) back in the barrel and assuring a seal-off through the upper sloped valve or head valve. (The head valve is required because O-rings are known to fail and the venting aperture(s) could easily leak fluid.)
It is important to understand why the xe2x80x9csafety-pinxe2x80x9d is employed in all embodiments. It is possible, during the initial operation of a reciprocating pump for the pump to lift upward due to internal friction in the pump: this action would open the device and allow back flow. In the second embodiment the only set of apertures are much larger than the vent apertures of the first embodiment. If the venting apertures are exposed, produced fluid will constantly run backwards (through the device) and the pump will not be able to lift fluid to the surface. (A similar argument may be made for the dump apertures of first embodiment except that those apertures are ONLY opened when it is time to withdraw the pump.) Therefore, in order to assure that the production tubing will fill with fluid, a safety is employed. In the second embodiment, it must be noted that during xe2x80x9cventing operationsxe2x80x9d the operator must assure that makeup liquid is available to reverse flow down the production tubing. In a similar manner the entry pins (particularly useful when the device is used with barrel pumps) assure that the device will remain closed (sealed) while entering the well. These points will be explained in further detail.
The reverse flow will allow the hydrostatic head to U-tube within the annulus. The amount of reverse flow will be controlled by the length of time that the vent-dump apertures are held open. (Remember that makeup liquid must be provided.) Thus the reverse flow can wash flower sand from around the hold-down; thereby, reducing the total pull required to xe2x80x9cpopxe2x80x9d the pump loose and withdraw it from the well. The reverse flow can fully xe2x80x9cdumpxe2x80x9d the hydrostatic head and wash flower sand, if no makeup liquid is provided. The reverse flow can wash flower sand if makeup liquid is provided. Finally the reverse flow can position chemicals immediately above the hold-down when a combination of chemicals and makeup liquid is provided.
As will be described in the detailed description of the invention, the device (first two embodiments) may be employed to xe2x80x9cspotxe2x80x9d well treatment chemicals in the xe2x80x9cdead-spacexe2x80x9d (no general fluid movement) that exists between the seating nipple and the top of the pump barrel. It is known that corrosion occurs in this space and that chemicals cannot readily be spotted in the dead-space. The method of spotting treatment chemicals is a variant of the venting (flower sand) procedure.